Matrix acidizing, the process of injecting a formation stimulation fluid such as acid or other acid-forming materials that may react with minerals in the formation to increase the formation permeability, is a common method used to stimulate and enhance the production of hydrocarbons from a hydrocarbon producing formation and remove formation damage caused by drilling mud invasion and clay migration.
For most matrix acid treatments, acid is injected into the reservoir below or above fracturing rates and pressures. To obtain the maximum benefits of matrix acidizing, it is often desirable to treat the entire productive interval of the formation with the stimulation fluid. As the stimulation fluid is pumped, it will preferentially enter the interval of least resistance (lowest stress) or highest permeability and will react with the formation material and open additional flow paths. As a result, the high permeability interval or non-damaged zone receives most or all of the stimulation while the desired low permeability or damaged zones do not receive the desired stimulation. In most cases, the low permeability or damaged zone is the portion of the reservoir that will benefit the least from stimulation. Without proper diversion, the acid, by flowing to the higher permeability zone, leaves the low permeability zone untreated.
Acid treatment is further used to remove formation damage. Standard sand control treatments often use high rate water packs. Before or after placement of gravel with a completion fluid, low-density brine or a linear gel, a large acid treatment is typically pumped to remove the near wellbore formation damage or skins encountered in perforation wells. Thus, a clay acid package is often pumped into the formation before the gravel pack to stabilize the residual clay. The results of these treatments are often directly related to the ability of the acid to remove the near-wellbore damage and connect the wellbore to the formation. In addition to determining the most effective combination of acid blends and volumes for each particular reservoir, treatment design and planning is often performed in order to ensure that the acid is placed across the entire interval. Such staging of acid treatment across the entire interval further serves to treat the damaged portion of the sands.
The successful acid placement in matrix treatments of open hole horizontal wells is even more difficult due to the length of the zone treated and potential variation of the formation properties. A successful diversion technique is critical to place the acid to the location where damage exists. For an ideal acid treatment on a long heterogeneous reservoir, one would prefer the majority of the acid to be injected into damaged or low permeability intervals; the minimum amount of acid being spent in the clean or undamaged reservoir. However acid, a nonviscous fluid, enters into the region with the lowest stress contrast which unfortunately is typical of the cleanest interval or the partially depleted sand. In order to re-direct the stimulation fluids from the non-damaged intervals into the damaged intervals, a pressure differential across the high permeability or non-damaged intervals is preferably created. This pressure differential typically forces the stimulation fluid into new portions of the reservoir that otherwise would not receive the stimulation fluid. Until a sufficient pressure differential is built up in this region, the fluid continues to be injected into the high permeability zones of the interval.
In light of such difficulties, operators and service companies typically attempt to stagger the introduction of acid fluid into damaged intervals. Such methodology more effectively treats all of the requisite intervals. In conjunction with the acid staging of the acid volumes, diverter stages are often pumped to temporarily plug the zones that are taking the acid. Rate increases during the treatment to increase injection pressure and cause diversions also are often attempted. Depending on the formation condition, various diverting techniques, such as particulate diverting agents, or viscous acids, have been used both successfully and unsuccessfully in gravel pack and stimulation treatments for numerous years. With many options of chemical diverting or bridging agents available, the type of product used varies from application to application and in some cases may even cause formation damage by the chemical residues. Previous works also established the model and practice to control the pumping rate to achieve the desired diversion.
The overall success or failure of many acid treatments is often judged by the ability to inject or direct the acid into the damaged or lower permeability zone. Without good diversion, the results of the acid treatment often lead to either incomplete damage removal and/or requirements for uneconomical volumes of treatment fluids. A well developed diverting agent, without formation damage after the treatment, is critical to the success of any matrix acid stimulation treatment and successful sand control completion.
Chemical diverting agents attempt to temporarily block the high permeability interval and divert the stimulation fluids into the desired low permeability or damaged intervals. It is desirable for these viscous gels to be stable at the bottomhole temperature and also to be removable from the formation rapidly after the treatment in order to eliminate any potential damage to the high permeability intervals. One chemical diverting fluid is a gelled hydroxyethylcellulose (HEC) pill wherein the viscosity of the pill influences the injection pressure of the interval it enters. As the pill enters the formation, the viscosity of the pill restricts the injection of other fluids into this area. As the injection pressure increases within this portion of the interval, other sections of the interval break down and begin accepting fluid. This technique is severely limited if the temperature of the gelled HEC exceeds 200° F. Above this temperature, the base viscosity and life of the pill is greatly decreased. Another problem seen with gelled HEC is that the blocked zone may be damaged from the polymeric residue left inside the porous media once the acid treatment is completed.
Foams may also be used as a diverting method for acid stimulation. Foams typically are generated through a blend of surfactants and/or a polymer. One of the popular diverting techniques in gravel packing and stimulation is the use of a foamed KCl or NH4Cl or a gelled HEC pill. When a fluid with high viscosity enters into the high perm zone which restricts the injection of other fluids into the same zone, the injection pressure begins to increase. As the overall injection pressure increases and overcomes the pressure threshold, the relatively low perm sections of the interval begin accepting the injected fluid. This technique is severely limited by temperature due to the instability of most foamed or gelled pills above 200° F. Above this temperature the base viscosity of the pill is greatly decreased and the life of the pill affected.
Another problem associated with foamed or gelled diverters is the lack of effectiveness in extremely high permeability reservoirs (>500 mD). Foamed or gelled HEC pills have little effect in high permeability reservoirs due to the ability of the formation to allow for “leak-off” of such fluids. Properly sized particles such as silica flour, calcium carbonate, or organic resins, with the ability to effectively pass through the gravel or perforations but plate or “bridge off” on the formation face, have been introduced in these environments. Even combinations of HEC diversion agents, nitrogen, and oil-soluble resins have been field tested. The main problems associated with the solid particles may be the improper sizing causing deep invasion problems that may not readily “clean-up” and cause further damage.
The addition of the polymer may also cause formation damage, as described above, while the use of nitrogen gas tanks and other associated pumping equipment are typically required for foam used as acid stimulation diverting agent. This may not be practical in many cases, especially for offshore acid treatments, as the operation is often limited by available deck space on the rig or vessel. In addition, foams typically become unstable above 250° F.
Another type of viscous fluid diverting agent used to assist in formation stimulation is a surfactant or surfactant mixture. One such viscoelastic fluid forms micelles. These wormlike micelles are sensitive to hydrocarbons. By utilizing this sensitivity, the fluid may selectively block water-bearing zones while the hydrocarbon-bearing zone is unaffected. However, this viscoelastic surfactant fluid typically cannot discriminate between zones with various permeabilities as long as the zones are hydrocarbon-bearing. Further, unlike polymer based fluids which rely upon filter cake deposition to control leak-off to the formation, viscoelastic surfactant agents control fluid leak-off into the formation through the structure size of the micelles. Micellar based VES fluids usually have high leak-off rates to the formation due to the small size of the wormlike micelles. Rapid weaving and breaking of these structures also limits the ability of the micellar based viscoelastic system to control fluid leak-off. The temperature limitations for such a system are generally around 200° F. due to the low stability of micellar structure.
With every type of diverting system available currently, clean-up only occurs with the inclusion of some type of outside source. Time, temperature, and interaction with either reservoir fluids or hydrocarbons are required to remove the diverting agent in place. For example, viscoelastic surfactant acid diverters typically require contact with the liquid hydrocarbon during flowback. Without this interaction the same factors that prevent fluids from entering a portion of the reservoir may also inhibit the ability of the reservoir to produce hydrocarbons.
In summary, the success of a stimulation treatment or gravel packed completion is often dependent on the ability of the diverting agent to force the acid treatment into different portions of the reservoir.
A need therefore exists for a method for diverting the stimulation fluid from high permeability zones to desired low permeability zones by a method which avoids the shortcomings of the prior art. This method should preferably use a composition that does not damage the formation, and is easily removed from the formation.
Another common stimulation technique used to enhance production of hydrocarbon from subterranean formations is hydraulic fracturing which is typically employed to stimulate wells wherein recovery efficiency is typically limited by the flow mechanisms associated with a low permeability formation. During hydraulic fracturing, a fracturing fluid, typically a gelled or thickened aqueous solution containing chemical agents as “breakers” and a suspended proppant, is injected into a wellbore under high pressure and is pumped at high rates. Once natural reservoir pressures are exceeded, the fluid induces a fracture in the formation and transports the proppant into the fracture.
The fracture generally continues to grow during pumping and the proppant remains in the fracture in the form of a permeable “pack” that serves to “prop” the fracture open. In this way, the proppant pack forms a highly conductive pathway for hydrocarbons and/or other formation fluids to flow into the wellbore. The fracturing fluid ultimately leaks off into the surrounding formation. The treatment design generally requires the fracturing fluid to reach maximum viscosity as it enters the fracture which affects the fracture length and width.
An important attribute of fracturing fluids is their ability to be recovered from the formation. Typically, the recovery of the fracturing fluid is accomplished by reducing the viscosity of the fluid to a low value such that it flows naturally from the formation under the influence of formation fluids and pressure. This viscosity reduction or conversion is referred to as breaking. Historically, the application of breaking fluids as fracturing fluids at elevated temperatures, i.e., above about 120–130° F., has been a compromise between maintaining proppant transport and achieving the desired fracture conductivity, measured in terms of effective propped fracture length. Conventional oxidative breakers may react rapidly at elevated temperatures, potentially leading to catastrophic loss of proppant transport. Further, encapsulated oxidative breakers often have limited utility at elevated temperatures due to a tendency to release prematurely or have been rendered ineffective through payload self-degradation prior to release.
Fracturing fluids composed of viscoelastic surfactant forming micelles have been reported in U.S. Pat. No. 6,435,277. Such micellar-type viscoelastic fluids have not been utilized widely in fracturing treatments of relatively low permeability formations because, amongst other reasons, materials have not been available that would enable the maintenance of needed viscosity at the elevated temperatures required for hydraulic fracturing operations. Further, such fluids are often subject to temperature and stability limitations and form emulsions which make the fluid recovery and fracture clean-up difficult. This patent further reports the previous limitation of viscoelastic surfactant fracturing fluids to formations containing clays as well as formations which require soluble salts for inhibiting hydration of clay materials.
A need therefore exists for surfactant based fluids having the ability to suspend proppants which are economical and which exhibit superior properties compared to existing products available on the market. In addition, such products need to maintain requisite viscosity at higher temperatures while being thermally stable without causing damage to the formation.